Oil retention and porosity evolution in organic-rich shales (original) (raw)
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Formation and occurrence of organic matter-hosted porosity in shales
International Journal of Coal Geology, 2018
Porosity within organic matter (OM) is considered to be the main site for gas storage (via fluid phase saturation of the pores and sorption on the pore walls) and thus its presence or absence is very critical for in-place gas assessment for organic-rich rocks. Numerous workers have suggested that OM-hosted porosity increases with thermal maturity mainly related to the process of bituminized organic matter cracking to gas. Comprehensive reviews of published literature enable us to conclude that organic porosity dominantly develops within bituminized organic matter (i.e., that portion that is petrographically identified, mainly based on its morphology, as solid bitumen (Mastalerz et al., 2018)) and primary (i.e, structured or amorphous) organic matter (kerogen) is mostly deficient in porosity. We show that in the same shale sample, structured kerogen shows no porosity whereas solid bitumen contains abundant porosity. It has been previously reported that sample preparation for SEM by ion milling may alter the organic matter. In this study, some adverse effects of ion milling have been observed by comparing SEM-visible pores of the same sample prepared by mechanical grind polish (MGP) and ion milling (IM) methods. Since solid bitumen is more labile, and probably more prone to chemical/physical alterations, we recommend that SEM observations of ion milled samples to be conducted with more attentiveness.
Marine and Petroleum Geology, 2009
The effect of shale composition and fabric upon pore structure and CH 4 sorption is investigated for potential shale gas reservoirs in the Western Canadian Sedimentary Basin (WCSB). Devonian-Mississippian (D-M) and Jurassic shales have complex, heterogeneous pore volume distributions as identified by low pressure CO 2 and N 2 sorption, and high pressure Hg porosimetry. Thermally mature D-M shales (1.6-2.5% VRo) have Dubinin-Radushkevich (D-R) CO 2 micropore volumes ranging between 0.3 and 1.2 cc/100 g and N 2 BET surface areas of 5-31 m 2 /g. Jurassic shales, which are invariably of lower thermal maturity ranging from 0.9 to 1.3% VRo, than D-M shales have smaller D-R CO 2 micropore volumes and N 2 BET surface areas, typically in the range of 0.23-0.63 cc/100 g (CO 2) and 1-9 m 2 /g (N 2). High pressure CH 4 isotherms on dried and moisture equilibrated shales show a general increase of gas sorption with total organic carbon (TOC) content. Methane sorption in D-M shales increases with increasing TOC and micropore volume, indicating that microporosity associated with the organic fraction is a primary control upon CH 4 sorption. Sorption capacities for Jurassic shales, however, can be in part unrelated to micropore volume. The large sorbed gas capacities of organic-rich Jurassic shales, independent of surface area, imply a portion of CH 4 is stored by solution in matrix bituminite. Solute CH 4 is not an important contributor to gas storage in D-M shales. Structural transformation of D-M organic matter has occurred during thermal diagenesis creating and/or opening up microporosity onto which gas can sorb. As such, D-M shales sorb more CH 4 per weight percent (wt%) TOC than Jurassic shales. Inorganic material influences modal pore size, total porosity and sorption characteristics of shales. Clay minerals are capable of sorbing gas to their internal structure, the amount of which is dependent on claytype. Illite and montmorillonite have CO 2 micropore volumes of 0.78 and 0.79 cc/100 g, N 2 BET surface areas of 25 and 30 m 2 /g, and sorb 2.9 and 2.1 cc/g of CH 4 , respectively (dry basis)-a reflection of microporosity between irregular surfaces of clay platelets, and possibly related to the size of the clay crystals themselves. Mercury porosimetry analyses show that total porosities are larger in clay-rich shales compared to silica-rich shales due to open porosity associated with the aluminosilicate fraction. Clay-rich sediments (low Si/Al ratios) have unimodal pore size distributions <10 nm and average total porosities of 5.6%. Siliceous/quartz-rich shales (high Si/Al) exhibit no micro-or mesopores using Hg analyses and total porosities average 1%, analogous to chert.
ACS Omega, 2022
Pore types and pore structure parameters are the important factors affecting the storage capacity of a shale oil reservoir. Pore morphology and mineralogical composition of shales have diverse effects on the upgrading of various phases of shale oil. To interpret the formation and distribution of different pore types and their structure parameters in the lacustrine calcareous shale, a combination of polarizing microscopy, X-ray diffraction, total organic carbon (TOC), field-emission scanning electron microscopy, and low-pressure nitrogen adsorption experiments were conducted on the Es3x shale of the Eocene Shahejie Formation in the Zhanhua Depression. The interpretations regarding pore types, pore structure parameters, and pore size distribution indicate that the pore morphology and pore size distribution in the lacustrine shale are very complicated and demonstrate strong heterogenic behavior. Inorganic pores (interparticle pores, intraparticle pores, intercrystalline pores, dissolution pores, and microfractures) are the most commonly distributed pore types in the studied shale. However, organic matter pores are poorly developed due to the lower thermal maturity of the Es3x shale. The Brunauer−Emmett−Teller specific surface and pore volume range from 0.026 to 1.282 m 2 /g (average 0.697 m 2 /g) and 0.003 to 0.008 cm 3 /g (average 0.005 cm 3 /g), respectively. The shape of the pores varies from slit-like to narrow slit. Different minerals develop different types of pores with various sizes extending from micropores (<2 nm), mesopores (2−50 nm), to macropores (>50 nm). The relationship between mineral components and pore parameters indicates that the carbonate minerals act as the main contributors to the formation and distribution of different pore types in the studied shale. Pore volume and the pore specific surface area did not show a good relationship with mineral composition and TOC due to disordered pores, but pore size shows a good relationship with mineral composition and TOC of the Es3x shale. The whole pore system description showed that the mesopores and macropores are abundantly distributed and are the main contributors to the pore system in the Es3x shale. A comprehensive understanding of the formation mechanism and structural features of various sized pores in a variety of different minerals can provide a good tool for the exploration and development of shale oil reservoirs.
Lithosphere
Organic matter (OM) pores are widely considered to be important for gas storage and transportation. In this work, we quantitatively analyze the pore structure of OM and its controlling factors through geochemical and petrologic analyses, optical microscope, OM isolation, and adsorption isotherms. These analyses were carried out on lacustrine shale samples from the Lower Cretaceous Shahezi Formation, which is located in the Changling Fault Depression in Songliao Basin. The results show that the content of soluble OM (SOM) is low, accounting for 0.26%-3.75% of total OM. The contribution of pore development from SOM itself is limited. After extraction of SOM by chloroform, pore volume (PV), specific surface area (SSA), and average pore diameter (APD) exposed to gas molecules greatly increase. The existence of SOM has an obvious effect on pores of >10 nm, especially the clay mineral-related pores that contribute the most to the total PV. The content of kerogen is higher than SOM and ...
Supercritical CH4 and subcritical CO2 and N2 gas adsorption measurements, combined with scanning electron microscopy (SEM) have been used to determine CH4 sorption capacity and pore characteristics for immature, mature and overmature shales from the Baltic Basin (Poland). Organic matter (OM) maturity exerts a dominant control on porosity evolution in micro- and mesoscale. In the Baltic Basin shales, the initial formation of micro- (< 2 nm) and mesopores (2–50 nm) occurs in the oil window (beginning of catagenesis, vitrinite reflectance Ro ~ 0.5-0.9%) due to primary cracking of kerogen that left OM highly porous. The expelled liquid hydrocarbons turned into solid bitumen that is responsible for pore blocking and significant decrease in micro- and mesopore volume in late mature shales (middle catagenesis Ro ~ 0.9–1.2%). Micro- and mesopores were regenerated in advanced catagenesis (Ro ~ 1.4–1.9%) due to secondary cracking of OM. The micropore volume in the Baltic Basin shales is mostly controlled by the OM content while the influence of clay content is minor and masked by OM. The CH4 adsorption in the Baltic Basin shales is predominantly controlled by OM micropore structure. The mesopore surface area and volume do not play an important role in CH4 sorption. The proposed adsorbed CH4 density equivalent (maximal absolute CH4 adsorption divided by micropore volume), revealed that the CH4 loading potential decreases in micropores with increasing maturity. The highest CH4 loading potential is linked to OM before metagenesis (Ro < 2%) where the adsorbed CH4 density equivalent was found greater than the density of liquid CH4. This suggests that in addition to physical adsorption, absorption (dissolution) of CH4 in OM occurs. When OM content was reduced by the treatment with NaOCl solution, CH4 adsorption decreased significantly, suggesting that OM microstructure has much higher adsorption potential than that of clay microstructure.
Natural gas can be stored as a condensed phase on shale matrix and organic materials or as conventional free gas in porous spaces (Lu et al., 1995). During the last decade, gas shale has been considered as important unconventional reservoirs in which part of the gas is stored in adsorbed state (Ross and Bustin, 2007). Several processes control fractionation and indeed retention mechanisms of gas hydrocarbons as the relative solubility of petroleum compounds in kerogen (Ritter, 2003), the gas adsorption on mineral surfaces (Brothers et al., 1991), in organic matter (Lamberson and Busting, 1993) or in nanopores of vitrinite (Ritter and Grover, 2005). In addition, several studies have paid attention to the distribution of pore system structures to further elucidate the gas storage process in these gas shales (Loucks et al., 2009). Most nanopores in these rocks are linked to the thermal cracking of the organic matter and are observed as intraparticle organic pores. This organic contribu...
International Journal of Coal Geology, 2014
Porosity in shales is important for storage of shale gas in reservoirs. As organic-rich shale thermally matures and enters the oil window, generated bitumen and oil can fill pore spaces, block pore connectivity, and reduce porosity. Low-pressure N 2 and CO 2 adsorption techniques were used to quantify mesoporosity (pore size 2-50 nm, accessible to N 2 and CO 2 ) and microporosity (pore size b2 nm, accessible to CO 2 only) in New Albany Shale samples of Devonian and Mississippian age from Indiana and Illinois ranging from marginally mature (vitrinite reflectance R o = 0.55%) to post-mature (R o = 1.41%). After measuring their original porosity, the shale samples were Soxhlet-extracted in refluxing dichloromethane (DCM, boiling temperature 39.6°C) to remove soluble oil/bitumen, vacuum-dried, and then re-measured for meso and microporosities. Subsequently, the same samples were Soxhletextracted in toluene (boiling temperature 111°C, with enhanced solubility of oil/bitumen), vacuum-dried, and again characterized porosimetrically. The maturation sequence of the original, non-extracted shales expresses a higher mesoporosity in lower maturity samples (vitrinite reflectance R o 0.55%, and 0.65%), and an intermittent decrease in mesoporosity in samples of post-mature stage (R o 1.15%) in two size fractions (4-mesh and 60-mesh). The intermittent decrease in mesoporosity is consistent with partial filling of pore spaces with bitumen and oil until secondary cracking reclaims some of the lost open pore space from liquid hydrocarbon phases. Organic matter (OM) transformation is thus a pivotal cause for the observed evolution of mesoporosity in original, non-extracted shales. Micropore volumes display a varying trend throughout thermal maturation, and are significantly controlled by total organic carbon content. Compared to 4-mesh sample fractions, a reduction in grain size of 60-mesh fractions for gas adsorption porosimetry prominently enhances mesopore volumes, whereas the effects on micropore volumes are variable. These findings may be associated with the fact that for smaller particles it is easier to attain equilibrium during gas adsorption porosimetry. Solvent extraction of soluble bitumen and oil from the shale samples generally opens additional pore space for N 2 and CO 2 adsorption, although the specific effects on mesoporosity and microporosity depend on maturity, total organic carbon (TOC) content, type of solvent, and grain size of the Soxhlet-extracted shales. The mesopore volume increases more in extracted samples with higher maturity, whereas the strongest gain in micropore volume is observed at elevated TOC content and highest maturity. Comparative porosities of original and Soxhlet-extracted shale samples constrain the evolution of porosity along maturation, as well as the effect of partial oil/bitumen filling and blocking of pores. This study also employs FTIR analyses of DCM and toluene Soxhlet extracts to differentiate low-temperature DCM-extractable, mostly aliphatic OM from higher-temperature toluene-soluble OM containing condensed cross-linked polyaromatic structures.
Diagenesis and kerogen release in oil- and gas-bearing shales
Acta Crystallographica Section A Foundations and Advances, 2014
The microstructure of pore space in sedimentary rocks and its evolution during reaction with pore- or fracture-contained fluids is a critically important factor controlling fluid flow properties in geological formations, including the migration and retention of water, gases and hydrocarbons. The size, distribution and connectivity of these confined geometries (pores, fractures, grain boundaries), collectively dictate how fluids of various chemistries migrate into and through these micro- and nano-environments, wet, and ultimately react with the solid surfaces. In order to interpret the time-temperature-pressure-fluid flow history of any geological system, the physical and chemical "fingerprints" of this evolution preserved in the rock must be fully explored over widely different length scales from the nanoscale to the macroscale. We are experimentally investigating these reaction-controlled changes in rock microstructure by conducting in-situ heating experiments on samples...
Impact of Shale Properties on Pore Structure and Storage Characteristics
All Days, 2008
Characterising the pore structure of gas shales is of critical importance to establish the original gas in place and flow characteristics of the rock matrix. Methods of measuring pore volume, pore size distribution, and sorptive capacity of shales, inherited from the coalbed methane and conventional reservoir rock analyses, although widely applied, are of limited value in characterising many shales Helium which is routinely used to measure shale skeletal and grain density, permeability and diffusivity, has greater access to the fine pore structure of shale than larger molecules such as methane. Utilizing gases other than He to measure porosity or flux requires corrections for sorption to be incorporated in the analyses. Since the permeability of shales vary by several orders of magnitude with effective stress, methods that do not consider effective stress such as crushed permeability, permeability from Hg porosimetry, and from desorption are of limited utility and may be at best ins...